Lundin Petroleum. Capital Market Day. 3 February Lundin Petroleum WF /02/16

Transcription

1 Capital Market Day 3 February 2016 WF /02/16 1

2 Capital Market Day Agenda 1. Introduction 2. Corporate Overview - Production - Reserves and Resources - Capital Expenditure and 2016 Work Programme - Financials and Funding Alex Schneiter - President and CEO Nick Walker - Chief Operating Officer Nick Walker - Chief Operating Officer Teitur Poulsen - VP Corporate Planning Mike Nicholson - Chief Financial Officer Break WF12155 p Norway Overview - Norway Development Projects - Norway Exploration 4. Malaysia Overview 5. Other Assets 6. Conclusion Kristin Færøvik - Managing Director, Lundin Norway Kristin Færøvik - Managing Director, Lundin Norway/ Per Øyvind Seljebotn - Reservoir Development Manager Halvor Jahre - Exploration Manager, Lundin Norway Nick Walker - Chief Operating Officer Nick Walker - Chief Operating Officer Alex Schneiter - President and CEO 2

3 Introduction Capital Market Day, 3 February

4 Strategy Grow production at low cost 2016 guidance 60,000 70,000 boepd at below USD 10/boe operating costs >150,000 boepd when Johan Sverdrup on full-field plateau Operating costs at significantly below USD 10/boe Continue to pursue an organic growth strategy Finding cost in Norway of USD 0.7/boe advantageous to M&A Four existing discoveries (Alta, Gotha, Luno II and Rolvsnes) feasibility studies ongoing Expenditure on organic growth is substantially discretionary financial flexibility at lower oil prices Retain geographical focus on Norway and Malaysia WF12155 p Continue strong focus on cost discipline and operating efficiency 4

5 Financial Flexibility Reserve base lending (RBL) remains core to our funding. USD 5 billion RBL accordion signed Robust balance sheet with liquidity headroom of MUSD 760 (RBL + exploration refund facility) Access to additional liquidity of MUSD 900 RBL accordion option (MUSD 700) Bertam FPSO sale (MUSD 200) Generating post-tax operating cashflow of USD 25 40/boe at USD 30 50/bbl Brent oil price No cash-taxes payable in Norway at USD 60/bbl Brent until Johan Sverdrup first oil WF12155 p

6 Resources Over 1 billion barrels of 2P reserves + contingent resources 2P reserves of 685 MMboe with 96% oil and 98% in OECD countries High quality oil selling at close to Brent parity R/P ratio ~30 based on 2016 production guidance Discovered 830 MMboe of commercial resources in Norway since inception Continue to generate exploration opportunities in Norway through high-grading of acreage Applied for high-quality acreage in Norway 23 rd Licensing round in southern Barents Sea WF12155 p

7 Developments Johan Sverdrup development a cornerstone for s valuation and financial flexibility Full field capex of USD~11/boe Full field opex of USD~5/boe lower at plateau Reduced capex has significantly lowered the breakeven oil price Developed and brought onstream 4 new fields over last 14 months Edvard Grieg reserves upgrade and production outperformance to date New infrastructure leading to low operating and maintenance costs Continue to invest in high return infill drilling opportunities in Alvheim area WF12155 p

8 Adjustment for Market Conditions Reduced discretionary spend to a minimum and focused spend on ongoing developments and operations E&A programme Maintain strategic activity in Southern Barents Sea, Utsira High and Sabah, Malaysia Reduced spend by 65% over 2015 Continued focus on reducing cost of operations to reflect market conditions Re-negotiating/re-tendering all contracts Achieving savings 20 65% Johan Sverdrup PDO cost reduction for Phase 1 1 NOK 123 Bn to NOK Bn, full field 2 NOK Bn to NOK Bn Flexible manpower contracting strategy Organisation size reduced by 30% G&A reduced by 35% WF12155 p USD : NOK 6.0 and nominal 2 USD : NOK 6.0 and real

9 Corporate Responsibility In Practice Promoting responsible business conduct through Employee awareness Internal processes Contractor management Stakeholder engagement Supporting international initiatives on Human Rights, Anti-Corruption and Climate Change Rated as Outperformer in the Sector by Sustainalytics WF12155 p

10 Corporate Responsibility Health, Safety and Environment Performance Three operated projects executed in the last year Personnel safety No serious incidents Focus on continuous improvement Process safety No serious incidents Strong HSE Performance Environmental footprint No recordable oil spill Focus on energy efficiency WF12155 p

11 Corporate Overview Production Capital Market Day, 3 February

12 2015 Production New projects Existing Asset Base 70 Malaysia, 17% 2015 Production 60 Indonesia, 5% (1) Bøyla first oil Jan 2015 Bertam first oil April 2015 E. Grieg first oil 28 Nov Mboepd Netherlands, 5% France, 9% Norway, 64% 30 Full year latest guidance 32,000 boepd production latest guidance: 32,000 boepd (1) WF12158 p Brynhild first oil Dec 2014 Q1 Q2 Q3 Q Actual actual production: 32,300 boepd (1) Achieved latest guidance Exit rate guidance of 75,000 boepd achieved in January 2016 with 3 rd Edvard Grieg well (1) Includes Indonesia divested assets 12

13 January 2016 Average Production: 64,000 boepd Net 90 January Net Production Mboepd Edvard Grieg Base Assets WF12158 p January

14 2016 Production Guidance 2016 production guidance: 60 70,000 boepd Production guidance reflects the ramp up of Edvard Grieg Net Production Guidance (Mboepd) Forecast 80 Jan Actual 64 Mboepd High Low 80 Malaysia 13% France 4% Netherlands 2% Alvheim hub 21% Brynhild 5% Edvard Grieg 55% WF12158 p Jan Q1 Q2 Q3 Q Forecast 0 14

15 Production Forecast from Ongoing Development 4 projects delivered in last 14 months Johan Sverdrup Phase 1 Johan Sverdrup Phase 2 150,000 boepd Other existing contingent and prospective resources not included in production forecast E Grieg, Bertam, Bøyla, Brynhild, Ivar Aasen WF12158 p ,000 (1) 30,400 (1) 23,800 (1) 32, , (1) Excluding divested assets (Russia) 15

16 Norway - Greater Alvheim Area 2015 Net Production 14,800 boepd Continued strong operating (uptime 94%) and subsurface performance Low cost of operations < 6 USD/boe Viper/Kobra project progressing to plan Portfolio of good in-fill drilling opportunities supported by 4D seismic New rig contract awarded for 4 wells from December Gross Alvheim Estimated Ultimate Recovery 2C Contingent Resources Cumulative Production End of Year 2P Reserves Alvheim (2 new wells) Boa Alvheim FPSO Kneler A East Kameleon Vilje MMboe % Kneler B Volund (at least 2 new wells) Alvheim Viper/Kobra (2 new wells) WI 2P reserves (MMboe net) (1) 15% Production Gas lift Water injection 17.9 WF12158 p PDO Year End Bøyla Volund Bøyla 35% 15% (1) Year end

17 Norway Greater Alvheim Area Continued Sub-Surface Success Viper / Kobra Viper 2015 Wells L4 1,500 bopd gross Kneler KA5 4,400 bopd gross 25/4-10S 25/ Wells/Projects Boa Kam North - first oil June successful pilots set-up future infill wells 3 branch producer with 5,600 metres net pay 25/7-6 Kobra Viper/Kobra Fields first oil December 2016 Tie-back via Volund Alvheim Field Drilled wells: Black Planned well: White CI:10m 2017 Wells 2 Volund infill wells 1 Alvheim attic well Volund West exploration BoaW Boa Kam N L4/EK2 BoaKamS Kn1/KA5 WF12158 p

18 Norway - Brynhild (WI 90%) 2015 Net Production 4,200 boepd Brynhild field Injector (A4) Haewene Brim FPSO performance improving Water handling constraints resolved Integrity issues being resolved Water injection commenced - remains a challenge Facilities uptime expectations reduced Reservoir performance indicates reduced connected volumes Gross ultimate 2P reserves reduced to 7.4 MMboe Production forecast reflects these issues Producer (A1) Producer (A3) 100% 2015 Brynhild Uptime Impacted by subsea integrity issue - now resolved December uptime 97% Producer & Injector (A2) 50% WF12158 p % Q1 Q2 Q3 Q

19 Norway - Edvard Grieg (WI 50%) Production Commenced - Well Potential >90,000 boepd gross Strong initial facilities and reservoir performance 3 wells on line total well capacity >90,000 boepd Significantly exceeds PDO expectation Better reservoir performance Facilities uptime outperforming 95% to date Anticipated to take 6 month to build to this level As per reservoir management plan, initial 2016 rates held below well potential until sufficient water injection available Plateau production of 100,000 boepd expected 2H 2016 boepd Edvard Grieg actual gross production (boepd) Facility capacity: 100,000 boepd 1 100,000 80,000 60,000 40,000 20,000 Average uptime to date: 95% OP2 online OP1 online OP3 online 0 Dec-15 Jan-16 WF12158 p Edvard Grieg capacity within the topsides facility 19

20 Malaysia - Bertam (WI 75%) 2015 Net Production 5,480 boepd Bertam field Bertam-3 A-15 Strong facilities performance 98% uptime Initially planned drilling programme complete A15 infill well drilling Q2 0 KM 1 Good reservoir performance decline slower than expected Cost of operations < 7 USD/bbl (excluding FPSO lease cost) boepd net 10,000 8,000 6,000 4, Bertam production Average 2015 uptime: 98% 2,000 WF12158 p Apr May Jun Jul Aug 2015 Sep Oct Nov Dec 20

21 Corporate Overview Reserves and Resources Capital Market Day, 3 February

22 2P Reserves 31 December 2015 France, 19.1 Total MMboe Netherlands, 1.9 Malaysia, 10.7 Aquitaine, 2.6 Paris Basin, 16.5 Edvard Grieg, Alvheim, 17.9 Volund, 9.6 Bøyla, 2.4 Ivar Aasen, 2.5 Brynhild, 5.1 Norway 95% of total reserves MMboe End Production Asset Sales Reserve Additions (excl. Sales/Acquisitions) End (1) Reserves increase (2) 292% Reserves replacement ratio (2) 4329% (1) Assumes closure of Singa asset sale WF12164 p Johan Sverdrup, Numbers in chart may not add up due to rounding Norway, (2) As per industry standards the reserve replacement ratio is defined as the ratio of reserve additions to production during the year, excluding acquisitions and sales. The reserves increase is calculated as the ratio of the reserves additions over the reserves adjusted for sales and production Numbers in chart may not add up due to rounding. 22

23 2P Reserves Changes Produced in 2015 Revisions Sales / Acquisitions Malaysia -3.1 Norway Netherlands +0.1 Indonesia -1.4 France WF12164 p Norway: + Johan Sverdrup matured from contingent resources to reserves + Volund infill well positive revision + Edvard Grieg positive revision - Brynhild negative revision MMboe Indonesia: Sale of assets 23

24 2P Reserves History MMboe Cumulative Production Malaysia Norway Tunisia Netherlands France WF12164 p Year End Excluding discontinued operations 24

25 Contingent Resources 31 December 2015 End 2015 Total 386 MMboe Luno II North discovery MMboe gross Contingent Resources Norway other, 25.5 Greater Alvheim Area, 1.8 Luno II North, 8.9 Luno II, 25.7 Russia, Rolvsnes oil discovery 3 16 MMboe gross Contingent Resources. Including prospective upside potential total gross resources range of MMboe Gohta, 51.3 Alta resource range unchanged Alta, 89.1 France, 13.1 Sabah gas, 31.8 Tembakau, 28.9 WF12164 p Numbers in chart may not add up due to rounding 25

26 Contingent Resources Changes Luno II Year end 2014 to Year end 2015 Rolvsnes Singa Disposition SE Tor SB MMboe Revision net to Lundin Norway: - Luno II and Rolvsnes discoveries - Disposition of SE Tor WF12164 p Malaysia: - Disposition of Singa - Farm down SB303 26

27 2016 Remaining Prospective Resources 2016 net unrisked prospective resources Norway SE Asia 400 Target Unrisked ~320 MMboe 1 Unrisked Million boe Neiden Filicudi Fosen Maligan net risked prospective resources Norway SE Asia 100 Target Risked ~87 MMboe Risked Million boe WF12164 p Excludes completed Bambazon well Neiden Filicudi Fosen Maligan 0 27

28 Drilling Schedule Country Norway Licence - Prospect Well type Operator PL544 - Fosen exp Lundin % 17 Norway PL609 - Alta-3 test app Lundin Norway PL609 - Neiden re-entry exp Lundin Norway PL533 - Filicudi exp Lundin LUPE WI % NUPR (1) CoGS (2) NRPR (3) 82 30% % 23 Malaysia SB307/308 - Maligan exp Lundin % Q1 Q2 Q3 Q4 Ongoing Ongoing Norway Alvheim Hub dev Det Norske Ongoing Norway Norway PL338 - Edvard Grieg JS Unit - Johan Sverdrup dev Lundin dev Statoil Malaysia PM307 - Bertam A15 dev Lundin Ongoing Netherlands exploration wells not included WF11117 p (1) Net Unrisked Prospective Resources (MMboe) (2) Chance of Geological Success (3) Net Risked Prospective Resources (MMboe) 28

29 Corporate Overview Expenditure and 2016 Work Programme Capital Market Day, 3 February

30 2015/2016 Capital Expenditure 2015 Guidance vs Actual 16% reduction on guidance 2016 Guidance 26% reduction on 2015 capital expenditure 2, , ,000 Exploration 1,800 1,800 1,800 Appraisal 1,600-16% 1,600 1,600 Development 1,400 1,400 1,400 Million USD 1,200 1,000-26% 1,000 1,200 1,000 Million USD WF12152 p Guidance Actual Guidance 0 30

31 2015 Development Activity 2015 Development: 1,060 MUSD Continental Europe, 20 Malaysia, 160 Norway, 880 Norway - USD 880 million Edvard Grieg - Topside Construction and Installation - Pipeline Installation - Development Drilling Johan Sverdrup - Subsea drilling template - Jacket & Topside construction Ivar Aasen - Jacket Installation - Development Drilling - Topside Construction Brynhild - Development Drilling 2 wells - Water injection facilities Bøyla - Development Drilling 1 well - Marine Installations Alvheim - 2 development wells completed France / Netherlands USD 20 million Malaysia USD 160 million - Bertam drilling - Installation - Bertam FPSO WF12152 p Development: 1,060 MUSD 31

32 CAPEX 2015 Guidance vs Actual 1,300 Capex Guidance vs Actual 1,300 1,250 1,250 1,200 1,200 Million USD 1,150 1,150 Million USD 1,100 1,100 1,050 1,050 1,000 1,000 WF12152 p Guidance Edvard Grieg Field & Pipeline Brynhild Johan Other Bertam Other 2015 Sverdrup Norway International Actual 0 32

33 2016 Development Activity 2016 Budget: 936 MUSD Continental Europe, 5 Malaysia, 28 Norway, 903 Norway - USD 903 million Alvheim Hub - USD 55 million - Development Drilling Edvard Grieg - USD 130 million - Development Drilling Johan Sverdrup - USD 705 million - Phase 1 Construction work - Phase 1 Development Drilling Ivar Aasen - USD 13 million - Topside Installation - Development Drilling Netherlands - 2 Offshore wells - L4a-K6 pipeline project France Paris Basin - Minimum capex spend Malaysia - USD 28 million Bertam - 1 development well 2016 Budget: 936 MUSD WF12152 p Budget: 936 MUSD Drilling Facilities Other

34 2016 Exploration & Appraisal Activity 2016 Budget 145 MUSD Other, 4 Norway, 115 Malaysia, 26 Norway Exploration - 1 re-entry & 1 well Barents Sea - 1 well Utsira High Appraisal Johan Sverdrup - Phase 2 Concept Selection Luno II - Development Feasibility Studies Alta/Gohta - Alta-3 re-entry and flow test - Development Feasibility Studies Netherlands - 2 onshore exploration wells Malaysia - 2 wells Sabah, East Malaysia WF12152 p Budget: 145 MUSD Targeting net unrisked 5 exploration wells in 2016 (1) resources of 320 MMboe (2) (1) Includes re-entry on Neiden and the completed Bambazon well. Excludes wells in the Netherlands. (2) Excludes completed Bambazon well and wells in the Netherlands. 34

35 Corporate Overview Financials and Funding Capital Market Day, 3 February

36 Funding Status and Guidance Cash Flow Generation Production set to double in 2016 Low cash operating costs (<10 USD/boe); no cash taxes in Norway Strong cash flow generation down to very low oil prices WF12168 p

37 2016 Forecast Netback (USD/boe) Forecast 2016 Actual 2015 Average Brent oil price USD/boe Revenue Cost of operations Tariff & transportation Production taxes Inventory movements Other - Base - Projects Cash Margin Netback WF12061 p (1) Adjusted for depreciation Production guidance 60,000 70,000 boepd 37

38 2016 Forecast Cost of Operations (including projects) 40 Malaysia, 15% 2016 Forecast 2015 Actual 40 Netherlands, 6% Norway, 68% 30 France, 11% 30 USD/boe (FPSO sale) (1) (1) (FPSO sale) USD/boe (2) WF12061 p Total Norway France Netherlands Indonesia (1) FPSO sale completion assumed end Q116 (2) Indonesia sale completion assumed 1 Jan Malaysia 0 38

39 2016 Forecast Cost of Operations Quarterly USD/boe Including Projects (FPSO sale) Base (FPSO sale) Including Projects Base USD/boe Forecast 2016 Including Projects (FPSO sale) Base Forecast 2016 (FPSO sale) Forecast 2016 Including Projects USD 9.10/boe 9 USD 8.10/boe 8 USD 7.60/boe Base Forecast USD 6.60/boe WF12061 p Q Forecast Q Forecast Q Forecast Q Forecast Note: FPSO sale completion assumed end Q116 and Indonesia sale completion assumed 1 Jan

40 2016 Forecast Depletion 35 Malaysia, 14% Netherlands, 2% France, 3% Norway, 81% 2016 Forecast 2015 Actual USD/boe USD/boe WF12168 p Total (1) Norway France Netherlands 0.00 Indonesia Malaysia (1) (1) Excludes depreciation of Bertam FPSO, Malaysia 0 40

41 2016 Forecast Tax Forecast 2016 Average Brent oil price USD/boe Current tax credit Deferred tax credit/charge Total WF12061 p

42 Norway Tax Value ~ USD 2 billion (1) of tax assets in Norway Undiscounted Norwegian Tax Value from historic capex spend as at 1 Jan 2016 (MNOK) 18, ,000 3,408 16,776 (1) 14, ,000 1,217 Million NOK 10,000 8,000 7,453 6,000 4,000 3,516 2,000 0 WF12168 p CT Historic Capex Depreciation at 25% (1) NOK 8.5/USD SPT Historic Capex Depreciation at 53% SPT Uplift Historic Capex Depreciation at 30% SPT Uplift Historic Capex Depreciation at 22% SPT Tax loss carry forward CT Tax loss carry forward Total Tax Value MMNOK 42

43 2016 Forecast Profit Netback (USD/boe) Forecast 2016 Average Brent oil price USD/boe Cash Margin Depletion/Depreciation G&A Financial items, net Profit/loss Before Tax Tax Profit/loss After Tax WF12061 p

44 2016 Forecast EBITDA Netback (USD/boe) Forecast 2016 Average Brent oil price USD/boe Cash Margin Netback General & Administration (1) EBITDA Netback WF12061 p (1) Adjusted for depreciation 44

45 2016 Forecast Operating Cash Flow Netback (USD/boe) Forecast 2016 Average Brent oil price USD/boe Cash Margin Netback Cash Taxes Operating Cash Flow Netback Strong cash flow generation down to USD 30/boe WF12061 p

46 Funding Status and Guidance Liquidity and Balance Sheet Robust balance sheet with strong access to liquidity Reserve based lending remains core to our funding: USD 5.0 billion accordion signed Exploration refund facility Secured against 2015 cash tax credit receivable December 2016: MUSD 250 facility size Bertam FPSO sale Infrastructure asset not linked to oil prices non core activity Releases additional liquidity in 2016: MUSD 200 No other debt instruments in the capital structure (full optionality) WF12168 p

47 Year End 2015 Liquidity RBL New 7 year facility signed Supported by 23 international banks USD 5.0 billion accordion facility Johan Sverdrup included as a borrowing base asset Initial commitments > USD 4.3 billion Optionality to bring in additional commitments Designed to fund Johan Sverdrup through to first oil 5 year grace period (no amortisation) Attractive margin: 315 bps WF12168 p More flexible covenant package to reflect growth profile 47

48 2016 Funding Liquidity MUSD 6, ,000 4, ,000 3,858 3,786 3, million (committed) 1.65 billion (committed plus optional) 2,000 Available Liquidity Headroom 1,000 0 RBL ERF RBL Accordion Bertam FPSO sale RBL Cash Net Debt 31/12 WF12168 p Sources of Liquidity 48

49 2016 Forecast Funding & Liquidity (USD/boe) Operating Cash Flow Netback Forecast 2016 Forecast 2016 Brent oil price (USD) Cash, General & Administrative / Financial Items Cash Flow Available for Investment Development Capex Exploration & Appraisal Capex Funding Requirement Available RBL Norway Exploration Refund Committed Financing MUSD WF12168 p FPSO Sale RBL Accordion Committed/Optional Financing

50 Funding Status and Guidance Liquidity and Balance Sheet Strong cash flow generation at very low prices Enhanced liquidity position with 760 MUSD of committed liquidity headroom Options to increase by a further 900 MUSD through RBL accordion and FPSO sale Full optionality to utilise additional debt instruments WF12168 p

51 Norway Overview Capital Market Day, 3 February

52 Norway Strategy Loppa High Barents Sea Focus on organic growth 2 key areas for exploration Utsira High Southern Barents Sea Norwegian Sea Southern Barents Sea Area 3 key areas for development/production Alvheim Area: 3 fields Utsira High: E. Grieg, Luno II, J. Sverdrup Loppa High: Alta/Gohta Alvheim Area North Sea Norway Utsira High Area WF12160 p UK 52

53 Norway An Organic Growth Success Story 6 x3 Production growth since start of USD per barrel finding cost post tax Fields currently on production. Johan Sverdrup under development Million barrels of reserves and resources at end 2015 WF12160 p Exploration & Appraisal wells since

54 Norway Utsira High Resources and Upside Potential major operated acreage position ~2.7 billion boe of gross reserves under development 3 PDO approved Edvard Grieg, Ivar Aasen and Johan Sverdrup 44 MMboe of net contingent resources high margin barrels to existing infrastructure Luno II, Luno II North, Apollo, Rolvsnes PL779 Ivar Aasen PL501 Johan Sverdrup Unit Multiple drill-ready prospects Apollo PL338 3,000 Fosen currently drilling Utsira High Discoveries PL673 PL338C Edvard Grieg (Luno South) Rolvsnes Johan Sverdrup PL674 WF12112 pt2 p MMboe (gross) 2,500 2,000 1,500 1, Year End Luno II/North Johan Sverdrup Apollo Ivar Aasen Edvard Grieg PL359 PL778 Fosen prospect PL544 Luno II Luno II North PL815 PL410 PL265 Norway North Sea 0 KM 10 PL501B 54

55 Norway Southern Barents Sea Southern Barents Sea Area Norway Southern Barents Sea Underexplored ~ 100 wells licences Operator Oil Partner Gas 5 recent oil discoveries + 2 gas discoveries Prospect Licenced Area 23 rd Round Blocks Industry Broadband 3D Seismic Hoop Area Southeast Barents Sea is a major licence holder in the Loppa High area Loppa High Area Wisting discovery Barents Sea 23 rd licensing round applications submitted in Dec 2015 Johan Castberg discoveries PL609 Neiden Prospect Alta & Gohta discoveries WF12112 pt2 p ~ 1 billion boe discovered over last 4 years Snøhvit Area PL708 Goliat development 0 KM

56 Norway Organisational Capability Gross discovered resources as operator, source NPD Others 28% Exploration Statoil 26% 46% (2) Exploration wells 50 Drilling 35% commercial success Edvard Grieg Development Development WF12160 p Operations Edvard Grieg Uptime [%] Dec 15 Jan 16 (1) (2) Gross discovered resources as operator, source NPD Assumes 100% of Johan Sverdrup 56

57 Norway Development Projects Capital Market Day, 3 February

58 Norway Development Projects Southern Barents Sea Area (Alta/Gohta) Norway Ongoing Norwegian developments Edvard Grieg (Lundin 50% operator) Ivar Aasen Unit (Lundin 1.385%) Johan Sverdrup (Lundin 22.60%) Appraisal projects: Luno II (Lundin 50.0%, operator) Alta/Gohta (Lundin 40.0%, operator) United Kingdom Ivar Aasen Unit Utsira High Area North Sea Stavanger WF12165 p Development Budget: MUSD 905 Edvard Grieg Luno II Johan Sverdrup Norway 0 KM 40 58

59 Norway Edvard Grieg Development Edvard Grieg Schematic Edvard Grieg Platform Ivar Aasen Platform Lundin interest: 50% (operator) OMV 20%, Wintershall 15%, Statoil 15% Gas Export to SAGE Ivar Aasen Oil Export to Grane 2P reserves: 206 MMboe gross Plateau production: 100,000 boepd gross Luno South Edvard Grieg First oil achieved 28 November 2015 Capital costs: NOK 26 billion Edvard Grieg Platform Drilling 14 wells from jack-up rig development drilling continues through 2017 One appraisal well in south east of the field successfully drilled - reserves upgraded (+ 20 MMboe gross compared to end 2014) WF12165 p

60 Edvard Grieg Project Update Edvard Grieg CAPEX 1 Latest Historic 2016 Future 26.0 Project delivered on schedule and on budget 3 wells online, drilling performance on schedule PDO Facilities Drilling Pipelines Other Nominal Gross (billion NOK) Project is 96% complete, project close out continues into 2016 Power generation final commissioning Water and gas injection startup Commissioning and tie in of future wells throughout 2016/2017 High quality facilities as demonstrated by uptime WF12165 p

61 Edvard Grieg Production Performance Edvard Grieg gross production (boepd) 100,000 Facility capacity: 100,000 boepd 1 Production Strong initial facilities and reservoir performance Facilities uptime outperforming 95% to date Anticipated to take 6 month to build to this level 3 wells on line total capacity >90,000 boepd PDO basis 24,000 boepd per well Gross Production [boepd] 80,000 60,000 40,000 OP1 online OP2 online OP3 online Better reservoir performance lower pressure decline As per the reservoir management plan, initial 2016 production rates will be held below well potential until sufficient water injection capacity is available 20,000 0 Nov-15 Dec Jan drilling programme - 5 wells 3 water injectors and 2 producers Currently drilling first water injector 100% Edvard Grieg uptime (%) Average uptime to date: 95% Uptime Uptime [%] 50% WF12154 p % Nov-15 Dec Jan-16 1 Edvard Grieg capacity within the topsides facility

62 Edvard Grieg Positive Appraisal and Development Drilling Results Drilled Producer Planned Producer Planned Water injectors Tellus 7 new wells since the PDO 16/1-18 appraisal (2014) Proved a back basin in the eastern part of the field 16/1-15&15A - 16/1-23SE appraisal (2015) Confirmed similar reservoir to the 16/1-18 well (A02) WI-1 OP1 (A11AT2 ) Development pilot wells A10 & A11 (2014/2105) Confirmed the extent of the high quality sands across the core of the field (A01) WI-2 16/1-13 A11 OP4 (A20) 16/ horizontal producers OP1, OP2 and OP3 (2015/2016) OP2 (A06) 16/1-18 Reserves revision end MMboe gross 2P reserves additions (A05 ) WI-3 16/1-8 OP3 (A10A) OP10 (A19) 16/1-23S WF12165 p Edvard Grieg 62

63 Edvard Grieg First Three Producers All three wells are high rate producers with petrophysical properties in line with, or better than, expectation OP1 (A11AT2 ) Reservoir pressure decline trends more favorable than expected OP2 (A06) OP3 (A10A) WF12165 p

64 Edvard Grieg 2016 Drilling Programme Injectors WI-1 currently drilling WI-2 and WI-3 to be drilled in 2016 Production capacity will be constrained while water injection capacity builds (A01) WI-2 (A02) WI-1 16/1-13 OP1 (A11AT2 ) 16/1-10 OP4 (A20) Oil producers 4 th producer (OP4) is planned as high rate producer 5 th producer (OP10) will be the first producer in the southern back basin (A05 )WI-3 OP3 (A10A) OP2 (A06) 16/1-18 Schedule Flexibility to adjust well schedule to optimise field performance 16/1-8 OP10 (A19) 16/1-23S WF12165 p

65 Norway Ivar Aasen Project PL338BS unitisation Lundin working interest 1.385% Ivar Aasen reserves Plateau Production 183 MMboe (gross) 65,000 boepd (gross), 1,300 boepd (net) Norway - Southern Utsira High KM PL779 PL673 PL265 PL338 Johan Sverdrup Apollo Johan Sverdrup Unit Edvard Grieg PL674 PL338C PL501B PL Ivar Aasen Operator PL501 Partner First oil Q topsides construction 92.5% complete PL778 Luno II discovery PL544 PL410 Norway North Sea Jacket Installation complete Drilling Commenced Q Ivar Aasen platform Edvard Grieg platform Edvard Grieg providing processing services to Ivar Aasen (process fluids + export) Total Capex (gross) 26.1 BNOK 1 Project on Schedule for 4Q16 First Oil WF12165 p Nominal 65

66 Norway Johan Sverdrup Development PDO Submitted Phase I PDO Approval Phase I PDO Submission Phase II First Oil Phase I First Oil Phase II Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q Q1 Q2 Q3 Q to Mongstad oil terminal to Kårstø gas terminal Phase 1 Gross Production Level: approx. 380,000 bopd Field centre (4 platforms) & oil/gas export pipelines 35 wells (16 producers, 18 injectors, 1 observation well) First oil end 2019 Full field Gross Reserves Range: billion boe Gross Plateau Production : ,000 boepd WF p Johan Sverdrup Phase 1 Layout 66

67 Norway Johan Sverdrup Key Points Largest Phase 1 development on the NCS Major importance to all stakeholders This project attracts the A-team from all companies and suppliers involved Up to 40% of NCS oil production at plateau PDO approved and full field reserves are booked million boe (2P net to ) Reduced capex has significantly lowered the breakeven oil price Processing platform Wellhead & Drilling platform Living Quarter Riser platform WF p

68 Norway Johan Sverdrup Development Johan Sverdrup core Sheet-like sand with large-scale lateral continuity (200 km 2 ) Extremely high permeability average 21 Darcy to >50 Darcy Connectivity over the entire structure High recovery factor and high well rates Johan Sverdrup Unit Norway WF p Johan Sverdrup Working Interest Lundin Norway Statoil Petoro Det norske Maersk Johan Sverdrup Unit 22.6% 40.03% (OP) 17.36% 11.57% 8.44% 68

69 Norway Johan Sverdrup Phase 1 Development Project is progressing to schedule: PDO approved by MPE in August 2015 Major contracts awarded Pre-drilling to commence Q Production start-up Q Costs are coming down: Phase 1 gross CAPEX reduced from NOK 123 billion to NOK billion 1 (12% saving) Phase 1 facilities de-bottlenecking measures approved which will increase Phase 1 production capacity Indicative FX split on CAPEX USD 20% Other 20% NOK 60% Pre-drilling template installation WF p nominal, operators latest estimate 69

70 Norway Johan Sverdrup Full field (Phase 2) Development Phase 2 - Final Concept Select Q4 2016: Full field process capacity Mbopd Production start-up 2022 Full field CAPEX significantly reduced to NOK billion (including Phase 1) 1 Due to market conditions and optimised facilities scope Phase 1 facilities WF p USD : NOK 6.0 and real

71 Norway Utsira High - Luno II Discovery PL359 Luno II (Lundin 50% operated) Top Basement (base reservoir) map D Luno II North oil discovery well 16/4-9S drilled in 2015 Well encountered a 23 metre oil column in a separate segment to the Luno II discovery and tested at 1,000 bopd 16/4-9S C 16/4-6S Luno II Gross contingent resources for Luno II North: MMboe Gross contingent resources for entire Luno II discovery: MMboe /1-14 (Apollo) Edvard Grieg 16/ / /1-4 16/ / / / / / /4-8S B A Potential subsea tie-back to Edvard Grieg platform Development concept studies being progressed Target to fill Edvard Grieg facilities once Edvard Grieg comes off plateau 338 C 359 D Edvard Grieg Sør 16/ km 16/4-5 16/4-3 16/4-9 C 16/4-6 Luno II WF12165 p KM 4 16/4-1 B 16/4-6 S (Luno II) 16/4-8 A 16/5-5 71

72 Southern Barents Sea Area Norway - Southern Barents Sea An Emerging Major Production Area Norway Johan Castberg discoveries 550 MMboe (1) Significant discovered resources Pipeline of developments Snøhvit online since 2007 Goliat start-up 2016 Johan Castberg expectation of concept selection in 2016 Alta & Gohta discoveries MMboe (2) Goliat development Snøhvit Fields 1,670 MMboe (1) WF12161 p Alta & Gohta Alta gross contingent resources unchanged at MMboe will review following 2016/2017 appraisal programme Gohta gross contingent resources MMboe Development feasibility study ongoing Long term well test under evaluation Original recoverable oil equivalents (ref. NPD) (2) Gross contingent resources range Snøhvit Area 179 MMboe (1) Barents Sea Melkøya LNG plant Hammerfest (1) 0 KM 50 72

73 Norway Exploration Capital Market Day, 3 February

74 Norway Strategy Loppa High Barents Sea Southern Barents Sea Area Focus on organic growth Inverted highs 2 key areas for exploration Utsira High Southern Barents Sea Application of latest technology Alvheim Area North Sea Norwegian Sea Norway Utsira High Area WF12160 p UK 74

75 Norway Finding Cost and Value Creation most successful exploration company in Norway during the last decade 4.0 Requires participation in development phase Jotun Njord Goliat Statfjord Gyda Grane Oseberg øst Tyrihans Oseberg Sør Norne Murchison Tor Veslefrikk Gullfaks Heidrun Brage Alvheim Eldfisk Statfjord øst Fram Snorre Draugen Glitne Vigdis Balder Oseberg Ekofisk Tordis Gullfaks Sør Ula 0 Valhall 0.5 Statfjord Nord WF12112 pt1 p USD/boe Norway Big Fields tend to get Bigger Troll II Finding Costs (USD/boe) (1) Factor Change in Total Oil Reserves since PDO Continue to pursue value creation through exploration organic growth Norway fields bigger than 120 MMboe (1) Costs include cumulative exploration and appraisal costs since inception up to Discovered resources assume year end 2015 remaining 2P reserves for Edvard Grieg, Volund, Bøyla, Brynhild and Johan Sverdrup. For Gaupe, Volund, Brynhild, Boyla and Edvard Grieg cumulative production up to is also included in reserves. Brynhild 2P reserves have been adjusted for 50% ownership at the time of making the discovery. Contingent resources for Gohta, Alta, Luno II, Luno II North and Rolvsnes have been estimated by. 75

76 Norway - The Most Successful Explorer Licence Acreage History Largest resources discovered on NCS (1) Cumulative km 2 25,000 20,000 15,000 10,000 Licence acreage APA 2015 BG ENI Esso Centrica VNG OMV Shell DEA Repsol Suncor 5, Det norske Total Lundin Petroleum 46% (2) Second most active explorer 50 No. exploration wells Wintershall 5% WF12160 p Cumulative Wells Commercial discovery Non-commercial discovery Dry hole % commercial success Statoil 26% (1) Gross discovered resources as operator, source NPD (2) Assumes 100% of Johan Sverdrup 76

77 Norway - Utsira High Area Evolution Operator Partner Oil Gas Prospect Lead NGL PL338 (2004) Edvard Grieg Discovery PL338 PL359 (2006) PL PL359 Ragnarrock Discovery 2007 PL PL409 (2007) PL410 (2007) North Sea 0 KM Ivar Aasen Discovery 2008 Apollo Discovery 2009 Luno South Discovery PL546 (2010) PL625 (2012) 025 PL409 PL338 PL265 PL359 PL PL544 PL544 (2010) PL546 PL501 Avaldsnes Discovery 2010 PL501 (2009) North Sea 024 I. Aasen Unit (001b,242,338BS,457) PL673 (2013) 015 PL673 Rolvsnes Discovery 2015 Luno II North Discovery PL625 PL338 PL338C PL359 PL265 PL Luno II Discovery 2013 PL544 PL674 PL501 Aldous Major Nth Discovery 2011 Geitungen Discovery 2012 North Sea PL501b Renamed In 2011 Johan Sverdrup 0 KM 8 0 KM 8 Aldous Major South Discovery 2011 J. Sverdrup Unit (2015) PL501b (2011) First licence (PL338) in 2004 First discovery (Luno) in 2007 Luno (renamed Edvard Grieg) doubles in size following appraisal 3 additional discoveries on western side of Utsira High The Avaldsnes structure is extended with another major discovery on Aldous MS. The giant field is renamed Johan Sverdrup Extensive appraisal on Johan Sverdrup WF12162 p major discovery (Avaldsnes) on eastern side of Utsira High 3 discoveries (Luno II & Luno II North, Rolvsnes) on south western corner of Utsira High PL338BS/Ivar Aasen Unitised 77

78 Norway - Utsira High Exploration KM 10 PL779 Ivar Aasen PL673 Apollo PL338 PL501 Operator Partner Prospect/lead Johan Sverdrup Unit Multiple drill ready prospects Tie-back opportunities to new area infrastructure Luno II North discovery (16/4-9S) 15 km south of Edvard Grieg Contingent resource range MMboe gross Total Luno II discovery resource range MMboe gross Edvard Grieg South PL338C Rolvsnes discovery 0015 Luno II North discovery PL778 Edvard Grieg 0016 PL359 16/ /1-25 Luno II PL265 PL815 PL501 Johan Sverdrup PL674 PL501B North Sea Rolvsnes/Edvard Grieg South oil discovery (16/1-25S) Follow up to discovery well 16/1-12 (Edvard Grieg South) Weathered/ fractured basement reservoir Pressure data confirms communication with 16/1-12 Gross contingent resources 3 16 MMboe Including prospective upside gross resource estimate range MMboe gross PL544 Fosen prospect 16/4-7 Hordaland Rogaland Fosen Prospect Proposed Well Location WF12162 p Fosen prospect (currently drilling) Reservoir target Draupne to Hugin formation Gross unrisked prospective resources 192 MMboe CoS 22% Cretaceous Jurassic/Skagerrak SmithBank Paleozoic Fosen 12 km 78

79 Norway - Southern Barents Sea Resources Net Acreage (km2) Southern Barents Sea 6,000 4,000 Yet-to-find resources - Norway North Sea: Norwegian Sea: Barents Sea: 2, bn boe 5.2 bn boe 8.0 bn boe 0 n i nd Lu Recent southern Barents Sea discoveries Johan Castberg: Alta: Gohta: Wisting Central: Sentralbanken High 550 MMboe 224 MMboe MMboe MMboe Ongoing southern Barents Sea developments Goliat: 1.67 bn boe Nordkapp Basin Loppa High Johan Castberg Discovery 179 MMboe Bjørnøya Basin Producing southern Barents Sea fields Snøvit: Fedynsky High Wisting Discovery Tromsø Basin South Barents Basin Gohta Discovery Alta Discovery Tiddly Bank Basin Snøvit Area Goliat Field WF12161 p Hammerfest Basin Hammerfest Source: NPD 1 resource estimate 2C Norway 79

80 Norway Southern Barents Sea Loppa High Exploration & Appraisal Norway Loppa High Area 609 Børselv licences Operator Partner Oil Gas Gohta/Alta discoveries opens up the area Kramsnø Prospect for significant new discoveries Johan Castberg Neiden Prospect Alta appraisal programme to continue in 2016/2017 Multiple prospects identified programme: Alta-3 re-entry & test Neiden exploration re-entry Filicudi exploration well Alta/Gohta area development feasibility study Iskrystall Filicudi Prospect Favignana Drivis Formica Salina Procida 492 Skavl Ponza Rauto 609 B Lakselv North Lakselv South Rein Alta Discovery 805 Gohta Discovery 767 Loppa High Barents Sea 438 Skalle Hammerfest Basin WF12161 p SNØHVIT 0 KM 20 80

81 Norway Southern Barents Sea Loppa High Existing Discoveries Alta total resources: MMboe Alta Discovery: MMboe (1) PL609 (Lundin 40% operated) Discovery well (2014): 57m gross HC column tested 3,300 bopd First appraisal Alta -2 (2015): Tested 860 bopd oil & 650 Mcfd gas Second appraisal Alta -3 (2015): 120m gross HC column, no test due to time constraints Alta wells 1, 2 and 3 in pressure communication Re-enter Alta-3 to deepen and test Development feasibility studies ongoing, to be followed by further appraisal Development feasibility study ongoing Alta Discovery 2015 Alta-3 Appraisal (re-enter 2016) Gohta Discovery: MMboe (1) PL492 (Lundin 40% operated) Discovery well (2013): 100m gross HC column tested 4,300 bopd Appraisal Gohta-1 (2014): Tested 860 bopd condensate 2015 Alta-2 Appraisal (completed) Senilix well (1985) Gohta Discovery WF12161 p (1) Gross contingent resources Gohta Appraisal 81

82 Norway - Southern Barents Sea Alta Appraisal Significant discovery Alta wells 1, 2 and 3 in communication Alta Field Alta-3 re-entry and test in 2016 Alta saddle app. well PL609 OWC Further appraisal drilling in 2017 Alta-1 GOC Cross section over Alta Alta-2 Alta-1 Alta-3 Alta-2 Vol. distr. conglomeratic sandstones Approx GOC Approx OWC Alta-3 Re-entry & Test Senilix well Alta SW app. well PL609B TKobbe Conglomerates Klappmyss Havert Dolomite Ugle WF12161 p High Spec. 3D Seismic Ørn Top Permian Falk PL492 Potential appraisal wells 82

83 Norway - Southern Barents Sea Neiden Prospect Re-entry 2016 Børselv Tana PL609 (Lundin 40% operated) Carbonate prospect on trend with Alta/ Gohta Neiden Updip of Obelix well with oil shows in carbonate reservoirs Alta Gross unrisked prospective resources 204 MMboe, CoS 30% During 2015 drilled to just above reservoir target and suspended Gohta Børselv, +300 MMbbls Neiden, 204 MMbbls, Cos 30% Obelix WF12161 p

84 Norway - Southern Barents Sea Filicudi Prospect 2016 Well PL533 (Lundin 35% operated) Multiple prospects on trend with large Johan Castberg discovery Double flat spot on seismic reduces risk similar response at Johan Castberg Gross unrisked prospective resources 258 MMboe, CoS 25% Prospect trend potential >1 billion barrels Arbitrary Line Filicudi Favignana Procida Ponza 609 Arbitrary Line K1 K2 Balto Rauto Favignana S. Lakselv S. Filicudi Filicudi Sth Formica Salina W Formica K3 Salina W 533 K4 Salina Salina E. Gohta N / Njalia 609B Alta Flat Spot Flat Spot Vague Flat Spot Vague Flat Spot Comparable to spill point Structural spill point WF12161 p Gohta

85 Norway - Southern Barents Sea 23rd Licence Round licences Operator Industry Broadband 3D Seismic Partner Haapet High Sentralbanken High New acreage not previously open to exploration Veslekari Dome Svalis Dome The largest structures seen in decades Very exciting potential Awards late Q rd Round Blocks Fedynsky High Nordkapp Basin Loppa High Bjørnøya Basin Alta & Gohta Discovery Signalhorn Dome Snøvit Area Tromsø Basin Goliat Field Hammerfest Basin WF12161 p Hammerfest Norway Finland 85

86 Norway Exploration Summary Leading acreage position Utsira High Loppa High Continuing to build portfolio Licence rounds Business development Continuing programme focussed on core areas WF12160 p

87 Malaysia Overview Capital Market Day, 3 February

88 Malaysia 2016 Block Summary Core positions in Peninsular Malaysia and Sabah Total acreage is 28,000 km 2, second largest after Petronas 14.3 MMboe gross 2P reserves 96 MMboe gross contingent resources Broad strategic farm-down to Dyas - Strong technical non-operated partner - Spread risk in high equity blocks - Work together in new opportunities SB303 - Gas Holding Area (WI 55%) (1) PM328 (WI 35%) (1) Sabah Core Area 2 exploration wells PM319 (WI 85%) Penyu Core Area 1 development well Malaysia PM308A (WI 75%) PM307 (WI 75%) Bertam field Natuna Sea Malaysia SB307/308 (WI 65%) (1) Operator Partner 0 KM 400 WF12159 p Indonesia (1) Blocks farm-down to Dyas Indonesia 88

89 Malaysia Bertam Overview Bertam Development Facilities PM307-75% (operator), Petronas Carigali 25% 2P gross ultimate recoverable reserves: 16.4 MMboe 14.3 MMboe remaining as at 31 Dec 2015 First oil: 5 April 2015 Project delivered on budget and on schedule Wellhead platform 12 Horizontal wells with ESP s (1) Utilise 100% owned FPSO (2) 98% uptime since startup Bertam Location Map PM319 PM307 Sotong Field Tembakau Gas Discovery Malong Field Malaysia 0 KM 20 Gurita Bertam Oil Field WF12159 p (1) 1 well to be drilled in 2016 (2) Proposed sale announced to M3nergy PM308B PM308A Indonesia 89

90 Malaysia Bertam Field Reservoir Development PDO development drilling programme completed Bertam-3 appraisal well identified eastern extension of the field A15 infill development well to be drilled Q2 Field Extension Bertam-3 appraisal well A15 infill well Infill drilling opportunities being reviewed Infill drilling options 0 KM 1 WF12159 p

91 Malaysia Organic Growth Potential Low costs - low commitment opportunities PM328 Potentially material new channel plays PM328 SB307/308 Maligan 110 MMbbls (1) - currently drilling PM307 New high impact plays identified in Miocene channel systems Malaysia Natuna Sea Malaysia Sarawak Negotiating new high potential acreage with PETRONAS Indonesia Indonesia 0 KM 400 WF12159 p (1) Gross unrisked prospective resources Operator Partner 91

92 Other Assets Capital Market Day, 3 February

93 Overview France & Netherlands Long life steady production and cash flow " Low capital requirement Offshore France Netherlands Netherlands Onshore Hydrocarbon Type Oil Gas 2015 Production Net, boepd 2,730 1,746 2P Reserves Net (1), MMboe " " Best Estimates Contingent Resources Net (1), MMboe 13.1 Paris Basin Asset Description Exploration Mature low decline onshore production 1.1 Million acres Mature on/offshore production Aquitaine Basin France (1) End USD/boe France Netherlands " Revenue WF12163 p OPEX Cash Net Back KM

94 France Steady Value Creation 14.0 End Year Contingent Resources Aquitaine Basin Paris Basin 2015 Production: 2,730 boepd P Reserves: 19.1 MMboe Contingent Resources: 13.1 MMboe MMboe Operating cash flow MUSD 27 in Cumulative Production 10,000 8,000 France historical production (bopd gross) Aquitaine Basin Paris Basin End Year 2P Reserves Aquitaine Basin Paris Basin 30 bopd 6,000 4,000 MMboe WF12163 p ,

95 Netherlands Mature Gas Production 2015 Production: 1,746 boepd Netherlands 2P reserves history (MMboe) Cumulative Production Reserves 2P Reserves: 2.0 MMboe Operating cash flow MUSD 13 in 2015 (boepd) MMboe ,500 4,000 3,500 3,000 2,500 2,000 1,500 Netherlands historical production (boepd net) ,000 WF12163 p

96 Conclusion Capital Market Day, 3 February

97 Key Messages Europe s largest independent E&P company Consistent sustainable organic growth strategy going forward Strong production growth with low unit operating costs Strong balance sheet and liquidity position Strong value creation track record Continued strong focus on cost discipline and operating efficiency WF12112 pt1 p

98 Disclaimer This information has been made public in accordance with the Securities Market Act (SFS 2007:528) and/or the Financial Instruments Trading Act (SFS 1991:980). Forward-Looking Statements Certain statements made and information contained herein constitute "forward-looking information" (within the meaning of applicable securities legislation). Such statements and information (together, "forward-looking statements") relate to future events, including the Company's future performance, business prospects or opportunities. Forward-looking statements include, but are not limited to, statements with respect to estimates of reserves and/or resources, future production levels, future capital expenditures and their allocation to exploration and development activities, future drilling and other exploration and development activities. Ultimate recovery of reserves or resources are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management. All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations and assumptions will prove to be correct and such forward-looking statements should not be relied upon. These statements speak only as on the date of the information and the Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, operational risks (including exploration and development risks), productions costs, availability of drilling equipment, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, and financial risks. These risks and uncertainties are described in more detail under the heading Risks and Risk Management and elsewhere in the Company s annual report. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. Actual results may differ materially from those expressed or implied by such forward-looking statements. Forward-looking statements are expressly qualified by this cautionary statement. WF8278 p